Low Carbon Energy Group

The Low Carbon Energy Group consists of two programs – the Capture effort carried out by Bob Williams with colleagues Tom Kreutz and Eric Larson, and the Energy Storage program led by Craig Arnold. The Capture group focuses on carbon capture and storage (CCS) from large-scale fossil
fuel and biomass energy conversion systems, including electricity and synfuels plants. The Energy
Storage team seeks improved strategies for storing energy that are compatible with intermittent
renewable sources.

Messages

Fossil fuel-based low-carbon energy systems

The Capture group finds that leading companies in China and the U.S. using and/or producing
coal are intrigued with coal-based pathways to low-carbon fuels and electricity, as they consider
the learning opportunities inherent in large early-mover projects and the merits of U.S.-China
cooperation in exploring such pathways.

Biomass-based initiatives

The Capture group finds that near-term deployment of gasification-based coal-biomass systems that
coproduce low-carbon transportation fuels and electricity and store captured CO2 via enhanced oil
recovery can facilitate a transition to the profitable production of gasification-based pure biofuels
with carbon capture and storage (CCS). Photosynthetic CO2 storage for such systems implies that
these biofuels would have strong negative greenhouse gas (GHG) emission rates that can be exploited
to offset emissions from hard-to-decarbonize energy systems.

Energy storage for off-grid wind systems

New research shows that lithium iron phosphate systems are well-suited to off-grid wind applications,
and that the lifetimes of these batteries could be extended through constant-voltage charging.

Enhanced oil recovery applications of CO2 capture technologies

Attractive economics are key to the ultimate commercial success of the coal-based, low-carbon energy
systems providing synthetic liquid fuels and/or electricity that the Capture group has investigated.
Gasification is the key enabling technology. The group’s previous economic analyses have provided
a credible basis for understanding how advanced gasification-based energy systems compare with
one another, but estimates of absolute costs have to be reconciled with real-world experience in order
to provide a good understanding of costs for first-of-a-kind (FOAK) projects and the subsequent
evolution to mature technology costs.

A new project launched in 2013 is aimed at creating this understanding. In this project the capture
group is collaborating with Chris Greig, Director of the University of Queensland (AU) Energy
Initiative. Greig was formerly CEO of ZeroGen, Australia’s flagship 400 MW integrated gasification
combined cycle plant with CCS (IGCC-CCS). That project was ultimately cancelled (Nov. 2011)
because it was deemed to be too costly and the geologic formations targeted for CO2 storage were
judged unsuitable.

Recent coal gasification experience in the U.S. has been for power generation via IGCC. In June 2013,
the 618 MW Edwardsport (Indiana) IGCC plant (with CO2 venting) came on line; the 582 MW
Kemper County (Mississippi) plant, for which captured CO2 will be sold for enhanced oil recovery,
will come on line by December 2014 (Figure 1). Edwardsport ended up costing more than twice as
much as first estimated, and the same will be true for Kemper County. These cost overruns took
place even though the design studies were carried out by top-flight engineering firms.

The Capture group is pursuing a multi-pronged investigation into the costs of large energy projects.
The goals are to: 1) reformulate their methodology for estimating capital costs for FOAK gasificationbased
processes that match the best available empirical evidence; 2) understand in detail why FOAK
costs are so high; 3) identify the most promising opportunities for reducing costs via accumulated
experience (often termed “learning by doing”); and 4) clearly and quantitatively articulate a
methodology for estimating plausible capital costs for mature technologies starting from FOAK cost
estimates.

The researchers will strive to understand the cost overruns at the Edwardsport and Kemper County
projects, accepting that much of the desired cost information is closely held. The project will also
analyze data from available design studies carried out for projects that ended up being cancelled
(including ZeroGen).

An early finding from this project represents learning from ZeroGen. Greig spent tens of millions of
dollars on engineering studies for this project that probably looked in much more detail at costs than
was the case for the early design studies carried out for Edwardsport and Kemper County. These
studies suggest that the final costs of Edwardsport and Kemper may not be so surprising after all,
because the cost (in $/kW) of the ZeroGen IGCC-CCS (if built in the U.S.) would somewhat exceed
that of the Kemper plant.

CCS projects are being deployed at a much slower pace that had been anticipated—thus jeopardizing
the future of CCS as a carbon-mitigation option. Progress is slow largely because: (a) capital costs
for “early-mover” projects have turned out to be much greater than estimates made by industrial
bodies, government agencies and academic groups, and (b) such projects cannot go forward without
substantial subsidies that governments will have difficulty providing.

During 2013, Williams carried out a preliminary technology cost buydown analysis for costly FOAK
projects for several power-only systems with CCS and for the two coproduction systems listed in
Table 1. This study analyzed the potential role of government subsidies in enabling cost-reduction via
experience for systems selling captured CO2 for enhanced oil recovery (EOR) and thereby advancing
CCS technologies more rapidly.

Williams showed that, if there is “learning by doing” at the same rate as was achieved for the sulfur
dioxide (SO2) scrubbers at coal power plants, it is plausible that, in the absence of a price on GHG
emissions, government subsidies for a relatively small number of early-mover coproduction plants
could reduce costs to market-clearing levels for EOR market applications. However, such an outcome
is unlikely for new plants making only electricity.

This analysis suggests that coproduction systems be given careful scrutiny as candidates for cost
buydown via government subsidy. Unfortunately, the extent of cost reduction via experience is a
priori unknowable.

However, important insights into the cost buydown process can be gleaned from a consideration of
the costs and benefits of subsidies for FOAK coproduction plants. Assuming that these plants are
deployed as “rebuild” units at sites of old coal power plants that are retired, they would offer not only
carbon mitigation benefits but also significant public health benefits associated with PM2.5 air
pollution health damage costs avoided in generating electricity (Figure 2).

The main findings of this analysis for FOAK plants are:

The required large subsidies are likely to be less than the public benefits of carbon mitigation and
air pollution health damage cost avoidance;

If captured CO2 is sold for enhanced oil recovery, federal revenues (mainly corporate income
taxes) from new domestic liquid fuels produced would be comparable to required subsidies; and

Government can afford to “find out” what the rate of learning is by providing the subsidies
required because, in effect, providing the subsidies would be approximately “revenue-neutral” for
government.

The quantitative results of this analysis are shown in Table 2, the notes of which list the assumptions.

Expanding the US/China collaboration on clean, low-carbon energy from coal

During 2013, Williams urged officials at the Shenhua Corporation (a Chinese coal company -
the world’s largest) and at Southern Company (a large investor owned electricity utility in the
Southeastern United States) to consider collaborating to advance clean, low-carbon energy from
coal - adding a new industry-led, government-assisted, action-oriented initiative to the ongoing
China/US collaboration on clean coal technology. The proposed collaboration would build on the
strengths of the two companies:

CEO/President Dr. ZHANG Yuzhuo’s vision for coal’s future in a carbon-constrained world:“Clean coal conversion can lead to the realization of the transformation from high carbon,
to low carbon, to carbon free coal utilization with broad prospects for technological and
commercial markets in the future.”

Southern:

Has long operated a small US DOE national energy laboratory at Wilsonville, Alabama that is now
called the National Carbon Capture Center (NCCC);

Has brought to commercial readiness with long-term US DOE support KBR’s transport gasifier
(TRIGTM) for low-rank coals—a gasifier that has (as a result of discussions to date about a possible
Shenhua/Southern collaboration) generated considerable interest on the part of Shenhua for use
with its extensive low-rank coal resources (for which it believes no other commercially-ready
gasifier is suitable);

Will bring on line by the end of 2014 the Kemper County Project, the world’s first commercialscale
gasification power plant with CCS; this TRIGTM-based IGCC is uses Mississippi lignite and
sells captured CO2 for enhanced oil recovery (see Figure 1); and

Has conducted tests (2009-2012) on the NCCC experimental TRIGTM gasifier showing that up to
30% biomass can be cogasified in oxygen (as required for making synfuels) with low-rank coals—
without technical difficulty and resulting in no change in syngas quality.

Williams was inspired to encourage the collaboration when he visited the NCCC in April 2013 and
learned about successful TRIGTM tests with up to 30% biomass—a percentage that can lead to ~90%
reduction in GHG emissions for coal/biomass systems with CCS that provide transportation fuels
and electricity (CBTLE-CCS plants). This empirical work plus substantial experience with biomass
supply logistics (the US has several biomass power plants consuming 0.5 million tonnes of wood
per year) implies that the CBTLE-CCS concept is ready to be demonstrated at commercial scale.
Williams’ personal goal is to catalyze via the collaboration FOAK CBTLE-CCS projects in both the
US and China.

Williams has had several discussions with Southern and Shenhua officials regarding the possible
collaboration, including two private meetings with Dr. ZHANG Yuzhuo, who told Williams that
a first step should be to have a technical delegation from Shenhua visit the NCCC and Kemper
County IGCC-CCS project (see Figure 1), which he asked Williams to help arrange. This “Southern
tour” took place on 2-3 January 2014, with Kreutz, Larson, and Williams accompanying the four
Shenhua engineers. Subsequently, Southern and Shenhua have had discussions regarding possible
dimensions of a collaboration.

In late 2013, the US Departments of Defense and Energy issued a call for proposals on coal-based
technological pathways that could lead to commercial production of jet fuel with lower GHG
emissions than for crude oil-derived jet fuel and with the potential to be cost-competitive. In
response, in early 2014 the Capture group submitted a proposal (invited as a result of acceptance
by the funding agencies of a December 2013 Concept Paper outlining the proposed project) for
a prefeasibility study of a FOAK coal/biomass to jet fuel plant. The group has assembled a team
(including collaborators from Southern Company; Chris Greig and a colleague at Queensland
University in Australia; Worley-Parsons Engineering; and from the CMI Fluids & Energy Group,
Michael Celia and Karl Bandilla) to propose a commercialization analysis for a coal/biomass-to-jet
fuel facility at a Mississippi site located near a CO2 pipeline network that can deliver captured CO2
to enhanced oil recovery operations. The team will analyze alternative designs for a facility that cogasifies
local lignite and woody biomass and converts the resulting gas to a Fischer-Tropsch synthetic
jet fuel. Alternative system designs will be considered and one specific design will be modeled in
detail. If the project goes forward, it will represent a step toward the goal of launching FOAK CBTLECCS
projects in U.S. and China via the Southern/Shenhua collaboration.

Biomass-based strategies for reducing emissions in transportation

Global climate models project that negative emissions will be needed by the 3rd quarter of this
century to avoid dangerous warming. In 2013, the CMI Capture group teamed up with ecologists
David Tilman and Clarence Lehman at the University of Minnesota to submit a winning proposal to
the Stanford University Global Carbon and Energy Project (GCEP) for work to identify, analyze, and
articulate promising systems for negative carbon emission transportation energy by mid-century.

The project will begin in 2014. Its goal is to quantify and articulate for policy makers the extent to
which different biomass energy technologies with CCS (BECCS) are likely to be able to contribute to
meeting U.S. demands for liquid fuels later in this century. Two mechanisms for achieving negative
emissions will be studied: i) storage of photosynthetic carbon in biomass roots and soil (R/S) and ii)
geologic storage of CO2 captured during feedstock conversion (CCS), with particular attention to the
use of CO2 in EOR as a near-term, large-potential strategy for commercial introduction of geologic
CO2 storage.

Minnesota colleagues will develop a comprehensive understanding of the ecological dynamics and
R/S carbon storage potential with perennial grasses grown on degraded land in the U.S. that is
currently ill-suited for conventional agriculture. A comprehensive, multi-disciplinary set of new
sustainability metrics will be developed to characterize alternative biomass resource/conversion
systems in terms of lifecycle energy and GHG balances, ecosystem and land-use impacts, and
prospective economics.

Energy storage

Energy storage is playing an increasingly important role throughout the energy infrastructure, from
powering hybrid and electric vehicles to offsetting the inherent intermittency of renewable energy
generation. Unlike batteries for electronic devices, which can be charged using a pre-determined
protocol simply by plugging them into the wall, many of these applications are characterized by highly
variable charge and demand profiles. The Energy Storage Group led by Craig Arnold is working to
characterize how such variability in charging power affects battery behavior in order to improve
overall system efficiency and lifespan. This past year, work has been focused on understanding the
effects of variable charging on different battery chemistries and methods of controlling/improving
the capacity.

Lithium iron phosphate batteries under variable charging conditions

The optimization of energy storage in variable charging conditions requires a thorough understanding
of how semi-unpredictable charging affects measures of battery behavior and performance, including
lifetime, efficiency, charge acceptance, and voltage behavior. In this work, we have been studying
the effects of variable operating conditions on different battery chemistries with an eye toward
understanding their applicability for grid level and other applications.

We find that of the standard chemistries (lead-acid, lithium cobalt oxide, lithium nickel managenese
cobalt oxide, and lithium iron phosphate), the lithium iron phosphate is the most reliable in response
to variable charging. However, through this work we have also identified an important feature of
these batteries in that, similar to lead-acid cells, these systems exhibit a ‘memory’ effect, where the
available capacity depends on the charging-discharging history of the cell. Over time and cycle, the
storage capacity of the battery decreases as expected.

However, we find that when the cell is charged completely through a constant voltage step (e.g. charge
the battery to the cut-off voltage at constant current and then hold at that voltage), it is possible to
‘reset’ the capacity and provide a temporary increase in the storage capacity (Figure 3). These results
suggest that constant-voltage charging of lithium iron phosphate batteries could help maintain gridlevel
storage capacity at optimal levels, as well as extend the lifetime and reduce lifetime costs of
batteries in electric/hybrid electric vehicles.